1. Field of the Invention
The invention is related to processing well log data. More specifically the invention is related to a system for improving the correlation of well log data to seismic data.
2. Background of the Invention
To properly interpret seismic data it is important to establish a correspondence between the seismic data, which is recorded as a function of time, and velocity and density logs, which are recorded as a function of depth. Establishing this correspondence can be difficult, however, and a principal reason for this difficulty is that the velocity and density logs are responsive to variations in the subsurface which the seismic signal is unable to resolve, or to even detect.
Normally if seismic data and well log data are both available from a subsurface region of interest, the well log data are used in conjunction with the seismic data to locate a given bed in two-way travel time in order to map the subsurface. Actual velocity, density or impedance variations through the strata of the earth's subsurface can be determined from velocity and density log data. Forward modeling, based on the measured velocity and/or density logs, creates a synthetic seismic trace which is then compared with measured or recorded surface seismic signals from the region near the wellbore from which the log data were obtained. The process of tying synthetic traces derived from log data to seismic travel time is called calibration.
Velocity logs are used frequently in the geophysical industry to identify key reflection events, extract seismic wavelets, assist in the construction of velocity macro-models and as a source of rock property information for seismic modeling and reservoir characterization. Traditionally, proper matching of velocity and density log depths to seismic trace time is an important element of seismic interpretation, but today practitioners are also frequently called upon to determine the effects, on seismic data, of changes in the velocity and density due to changes in hydrocarbons, porosity or lithology. However, these changes which may occur in the real earth may or may not be resolvable, or even detectable, by the seismic data. Further, velocity and density logs often are very complicated, with many severe oscillations which may inhibit the interpreter's ability to determine what effect, if any, a single oscillation or a series of oscillations on a log will have on the actual seismic data. To make effective use of the correlations of seismic data with the well log data, a proper correlation needs to be established between the depth scale on the log data and the time scale on the seismic data, and a method is needed for determining which variations in the log will have corresponding noticeable changes in the seismic data.
Velocity logs are generated by a downhole tool (sonde) which typically is lowered into a wellbore to a selected depth and as the tool is then raised toward the surface, an acoustic signal is generated at a transmitting location on the logging tool, and detected at one or more receiving locations on the logging tool. Because the distance between the transmitting location and the receiver locations, as well as between the two receiving locations is known, by measuring the differential travel time of the transmitted signal, the velocity of the subsurface interval (either the compressional wave velocity or the shear wave velocity, as the case may be) between the receivers, may be determined. The frequency of the transmitted acoustic signal is typically about 10,000 Hz., and velocity measurements are made at intervals as small as 10 centimeters (3.937 inches).
Similarly, density is measured by a downhole tool (sonde) which emits gamma rays from a source and the returning gamma rays are detected by two gamma ray detectors. Dense formations absorb many gamma rays and return few, while lighter formations absorb fewer gamma rays and return more. If the tool is properly calibrated, a direct measurement of density can be obtained. Density measurements may be made at intervals as small as 10 centimeters.
Acoustic impedance is the product of density and compressional wave velocity, and may be determined from compressional wave velocity log and density log, measurements. Elastic impedance is the product of density and shear wave velocity, and may be determined from shear wave velocity log and density log measurements.
In contrast to well log measurements, a seismic signal is generated by injecting an acoustic signal from the earth's surface, which then travels downwardly into the earth's subsurface. When the seismic signal encounters an interface between two subsurface strata having different impedances, a portion of the acoustic signal is reflected back to the earth's surface, where the reflected energy is detected by a sensor. Because high frequency signals cannot penetrate the earth's subsurface to the depths of interest in many hydrocarbon exploration prospects, the maximum frequency of the detected seismic signal will typically be about 60 Hz, which means the bandwidth of the seismic data is several orders of magnitude less than the bandwidth of the recorded velocity or density log. Accordingly, the bandwidth of the downgoing seismic wavelet does not enable the seismic signal to resolve the very thin beds recorded by the velocity and density logs, and in many cases is scarcely able to even detect these thin beds.
Resolution and detection of the seismic method is discussed in an article by R. S. Kallweit and L. C. Wood, The limits of resolution of zero-phase wavelets, July 1982, Geophysics, Vol. 47, No. 7, pp 1035-1046. This article shows that the composite seismic response of a thin bed is partially annihilated by the reflection seismic method. This reduction in the returned reflection signal is due to the summation of two returning wavelets, resulting from reflections from the top and bottom of a single layer, that arrive at virtually the same time but with opposite polarity. For very thin beds, the time delay between the reflection from the top of the layer and the reflection from the bottom of the bed is very small, and the attenuation is nearly complete. As the thickness of the bed increases, however, the reflected signal is only partially attenuated. FIG. 1 shows the amplitude of the thin bed reflection signal normalized to the amplitude of the reflection signal that would be returned from a thick bed reflection interface. This normalized amplitude plot is referred to herein as the "tuning curve". The two-way travel time between the bottom and top of the thin bed layer is plotted across the abscissa of FIG. 1. As the separation between the top and bottom of the layer increases, the attenuation is lessened, until, at a specific separation, there is no reduction in signal amplitude, i.e., the tuning weight is equal to 1 (one). By "tuning weight" is meant maximum weight, at a given separation, of a composite waveform created when a unit amplitude zero-phase wavelet is convolved with a unit amplitude dipole (i.e., +1, -1). As the separation between the layers increases further, the amplitude actually increases until it reaches a maximum amplitude. At the time distance on this "tuning curve" where the maximum amplitude occurs, which is designated in FIG. 1 as "T.sub.R ", the signal reflections from the top of the layer and from the bottom of the layer become separated, and reflections from the top and bottom of the layer will appear separately in a recorded seismic signal. This time distance, T.sub.R, which is referred to herein as the resolution limit, is typically about 10 milliseconds. For a layer 10 feet thick, with a velocity of 10,000 feet per second, the two way travel time is 2 milliseconds, which is well below the resolution limit, T.sub.R, therefore, the seismic response of this layer will be greatly reduced. From this illustration, it is clear that the seismic signal may be greatly attenuated, and that the recorded seismic signal will not be able to resolve the signal returned from a layer through which the two way travel time (TWTT) of the seismic signal is less than T.sub.R.
In order to aid the practitioner in correlating the velocity and density logs with seismic data, methods have been utilized in the prior art to remove the high frequency portion of these logs. These prior art techniques are based on filtering of the log data. For example, a low pass filter has often been applied to the velocity or density logs. However, this approach removes jumps in the log data and it may introduce artifacts whenever velocity spikes occur on the log. Rather than removing the thin bed spikes, this method merely smooths the log data, so that error is introduced in adjacent locations and important jumps may be eliminated.
In another prior art filtering method, the median filter method, a moving window is applied to the log and the center value within this moving window is replaced with the median value within the window. This method will replace high frequency spikes with reasonable values and has the advantage of preserving jumps in the sonic log. Nevertheless, this technique employs no guiding principles on the correct amount of each spike and/or jump to preserve and, conversely on the correct amount to remove.
There remains a long felt need in the industry for an improved method for processing log data to assist the explorationist in correlating the log data with seismic data. It is an object of this invention to provide such an improved method.